U.S. patent application number 13/611567 was filed with the patent office on 2013-01-03 for methods for stimulating oil or gas production using a viscosified aqueous fluid with a chelating agent to remove calcium carbonate and similar materials from the matrix of a formation or a proppant pack.
This patent application is currently assigned to Haliburton Energy Services, Inc.. Invention is credited to Richard W. Pauls, Thomas D. Welton.
Application Number | 20130000913 13/611567 |
Document ID | / |
Family ID | 39968484 |
Filed Date | 2013-01-03 |
United States Patent
Application |
20130000913 |
Kind Code |
A1 |
Welton; Thomas D. ; et
al. |
January 3, 2013 |
Methods for Stimulating Oil or Gas Production Using a Viscosified
Aqueous Fluid with a Chelating Agent to Remove Calcium Carbonate
and Similar Materials from the Matrix of a Formation or a Proppant
Pack
Abstract
Methods for treating a subterranean formation can comprise
introducing a treatment fluid comprising dicarboxymethyl glutamic
acid (GLDA) or a salt thereof into a subterranean formation, and at
least partially removing an iron-containing material in the
subterranean formation using the GLDA. Treatment fluids used in the
methods may have a pH equal to or greater than about 2.
Inventors: |
Welton; Thomas D.; (Houston,
TX) ; Pauls; Richard W.; (Duncan, OK) |
Assignee: |
Haliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
39968484 |
Appl. No.: |
13/611567 |
Filed: |
September 12, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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11801209 |
May 10, 2007 |
|
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13611567 |
|
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Current U.S.
Class: |
166/307 ;
166/308.2; 166/308.4 |
Current CPC
Class: |
C09K 8/528 20130101;
C09K 8/86 20130101; C09K 8/536 20130101 |
Class at
Publication: |
166/307 ;
166/308.2; 166/308.4 |
International
Class: |
E21B 43/27 20060101
E21B043/27; E21B 43/22 20060101 E21B043/22 |
Claims
1.-27. (canceled)
28. A method comprising: introducing a treatment fluid comprising
dicarboxymethyl glutamic acid (GLDA) or a salt thereof into a
subterranean formation; and at least partially removing an
iron-containing material in the subterranean formation using the
GLDA.
29. The method of claim 28, wherein the pH of the treatment fluid
is equal to or greater than about 2.
30. The method of claim 28, wherein the pH of the treatment fluid
is equal to or greater than about 5.
31. The method of claim 28, wherein the pH of the treatment fluid
is between about 6 and about 12.
32. The method of claim 28, wherein the treatment fluid further
comprises water.
33. The method of claim 32, wherein the GLDA is present in the
treatment fluid at a concentration between about 1% and about 80%
by weight of the water.
34. The method of claim 32, wherein the treatment fluid further
comprises a surfactant.
35. The method of claim 32, wherein the treatment fluid further
comprises a component selected from the group consisting of a
surfactant, a water-soluble inorganic salt, a water-soluble
inorganic salt replacement, a viscosity-increasing agent, a
crosslinking agent, a breaker, a delayed release breaker, an
enzyme, an oxidizer, an additive for foaming, a gas, and any
combination thereof.
36. The method of claim 28, wherein the iron-containing material
comprises an iron-containing scale.
37. The method of claim 36, wherein the iron-containing scale
comprises an iron-containing compound selected from the group
consisting of iron carbonate, iron sulfide, iron oxides, and any
combination thereof.
38. The method of claim 28, wherein the iron-containing material is
present in a proppant pack.
39. The method of claim 28, wherein the iron-containing material is
present in fracture.
40. A method comprising: introducing a treatment fluid comprising
dicarboxymethyl glutamic acid (GLDA) or a salt thereof into a
subterranean formation; and at least partially removing a scale in
the subterranean formation using the GLDA.
41. The method of claim 40, wherein the pH of the treatment fluid
is equal to or greater than about 2.
42. The method of claim 40, wherein the pH of the treatment fluid
is equal to or greater than about 5.
43. The method of claim 40, wherein the pH of the treatment fluid
is between about 6 and about 12.
44. The method of claim 40, wherein the treatment fluid further
comprises water.
45. The method of claim 44, wherein the GLDA is present in the
treatment fluid at a concentration between about 1% and about 80%
by weight of the water.
46. The method of claim 44, wherein the treatment fluid further
comprises a surfactant.
47. The method of claim 44, wherein the treatment fluid further
comprises a component selected from the group consisting of a
surfactant, a water-soluble inorganic salt, a water-soluble
inorganic salt replacement, a viscosity-increasing agent, a
crosslinking agent, a breaker, a delayed release breaker, an
enzyme, an oxidizer, an additive for foaming, a gas, and any
combination thereof.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not applicable
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable
REFERENCE TO MICROFICHE APPENDIX
[0003] Not applicable
TECHNICAL FIELD
[0004] The invention generally relates to production enhancement to
increase hydrocarbon production from a subterranean formation. More
particularly, the invention relates to methods of treating a
portion of a matrix of a subterranean formation or a proppant pack
in a pre-existing fracture or perforation to increase permeability
and enhance production, some of which techniques are referred to as
near-wellbore stimulation.
SUMMARY OF THE INVENTION
[0005] According to the invention, a method for treating a portion
of a subterranean formation or a proppant pack is provided. In
general, the method comprises the steps of: (A) forming or
providing a treatment fluid comprising: (i) water; (ii) a chelating
agent capable of forming a heterocyclic ring that contains a metal
ion attached to at least two nonmetal ions; and (iii) a
viscosity-increasing agent; and (B) introducing the treatment fluid
into the wellbore under sufficient pressure to force the treatment
fluid into the matrix of the formation or the proppant pack.
[0006] Other and further objects, features and advantages of the
present invention will be readily apparent to those skilled in the
art when the following description of the preferred embodiments is
read in conjunction with the accompanying drawings
DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT
[0007] In general, the purpose of this invention is to improve
delivery of a chelating agent for production enhancement by
increasing the viscosity of the treatment fluid. A chelating agent
can be utilized to help dissolve and remove carbonates and other
minerals from the matrix of the subterranean formation or the
proppant pack. The concentration of the chelating agent is
sufficient to help dissolve a substantial amount of carbonate
material. The treatment fluid containing the chelating agent
includes a viscosity-increasing agent to help with placement of the
fluid into the formation or proppant pack or to help with diversion
of the treatment fluid. When the viscosity of the fluid is
increased or gelled, the treatment fluid can provide better
coverage and diversion, and thereafter be broken for flowback from
the well. The treatment fluid can be a single fluid that dissolves
calcium/magnesium/iron carbonate solids in the matrix of the near
region surrounding a wellbore, a pre-existing gravel pack, a
pre-existing perforation, or a pre-existing fracture or that
dissolves these solids in a proppant pack in a pre-existing
perforation or a pre-existing fracture. The treatment fluid
dissolves such solids at a controlled rate and under a wide range
of conditions, especially over a broad range of pH and time. The
invention can be advantageous because it can provide methods for
treating the matrix of a subterranean formation or a pre-existing
proppant pack for such purposes using treatment fluids that are
non-acid containing and non-corrosive.
[0008] The treatment methods according to the invention are
expected to be effective for applications associated with well
completion and remediation, including: removal of carbonate scale
from the formation and fractures in the formation; removal of
carbonate from formations or proppant packs where the carbonate
lines pore throats; stimulation for carbonate containing formations
where the use of acidic fluids might be problematic, for example,
in high-temperature formations due to reaction rates, or due to
corrosion, etc. For a stimulation treatment, the purpose is to
improve the skin of the matrix of the formation over its original
condition, and a greater depth of matrix penetration is desirable.
For a damage removal treatment, such as after a prior gel treatment
or completion damage, less depth of penetration can be sufficient
(all else being equal), where the purpose of the damage removal is
to get the permeability of the matrix of the formation back toward
its original condition. According to a presently preferred
embodiment, the treatment method is used as a remedial cleanup
after a prior stimulation treatment.
[0009] As used herein, the words "comprise," "has," and "include"
and all grammatical variations thereof are each intended to have an
open, non-limiting meaning that does not exclude additional
elements or steps.
[0010] In general, the new approach is a method for treating a
portion of a subterranean formation or proppant pack, the method
comprising the steps of: (A) forming or providing a treatment fluid
comprising: (i) water; (ii) a chelating agent capable of forming a
heterocyclic ring that contains a metal ion attached to at least
two nonmetal ions; and (iii) a viscosity-increasing agent; and (B)
introducing the treatment fluid into the wellbore under sufficient
pressure to force the treatment fluid into the matrix of the
formation or the proppant pack. As used herein, "into the matrix of
the formation or the proppant pack" means into the rock around the
wellbore, a pre-existing perforation, or a pre-existing fracture,
or into the matrix of a proppant pack in a gravel pack in the
wellbore, a pre-existing perforation, or a pre-existing fracture.
The method is adapted to be used after drilling a wellbore, either
during completion or remediation of a well.
[0011] It is believed that the chelating agent in the treatment
fluid can react with and dissolve calcium carbonate, magnesium
carbonate, dolomite, iron carbonate, and similar materials of the
formation to increase the permeability of the formation. It can
also be used to help remove carbonate from formations where the
carbonate lines the pore throats in the matrix of the formation,
whereby the permeability of the formation can be increased and
hydrocarbon production enhanced. It is desirable to allow the
treatment fluid to contact the matrix of the formation or the
proppant pack for a sufficient time to dissolve such carbonate
materials. CaCO.sub.3 is known as limestone; and
CaMg(CO.sub.3).sub.2 is known as dolomite or dolomitic limestone,
both of which are minerals that are often present in subterranean
formations or which may precipitate from water as scale in
subterranean formations or proppant packs. Typical scales are of
calcium carbonate, calcium sulfate, barium sulfate, strontium
sulfate, iron sulfide, iron oxides, iron carbonate, various
silicates and phosphates and oxides, or any of a number of
compounds insoluble or slightly soluble in water. Although it may
not be expected to dissolve all of the components of scale, the
chelating agent can be helpful in removing calcium carbonate,
magnesium carbonate, dolomite, iron carbonate, and similar
materials of scale.
[0012] As used herein, to chelate means to combine a metal ion with
a chemical compound to form a ring. "The adjective chelate, derived
from the great claw or chela (chely-Greek) of the lobster or other
crustaceans, is suggested for the caliper like groups which
function as two associating units and fasten to the central atom so
as to produce heterocyclic rings." Sir Gilbert T. Morgan and H. D.
K. Drew [J. Chem. Soc., 1920, 117, 1456].
[0013] Preferably, the water further includes a water-soluble
inorganic salt dissolved therein. The purpose of the inorganic salt
can be, for example, to weight the water of the treatment fluid or
to make the treatment fluid more compatible and less damaging to
the subterranean formation. It should be understood, of course,
that a source of at least a portion of the water and the inorganic
salt can be selected from the group consisting of natural or
synthetic brine or seawater. Inorganic salt or salts can also be
mixed with the water of the treatment fluid to artificially make up
or increase the inorganic salt content in the water. Alternatively
for these types of purposes, a water-soluble salt replacement can
be utilized such as tetramethyl ammonium chloride (TMAC) and
similar organic compounds.
[0014] It is a particular advantage of the method according to the
invention to be able to help remove carbonate and similar materials
without the use of strongly acidic treatment compositions, that is,
without the use of treatment compositions having a pH less than 2.
According to a preferred embodiment of the invention, the pH of the
treatment fluid is equal to or greater than 2, which is above the
pH of strong inorganic acids that have been used to help dissolve
and remove carbonate materials from the formation.
[0015] More preferably, according to the invention, the pH of the
treatment fluid is equal to or greater than 5, which is well above
the pH of spent acid fluids used for the purpose of removing
carbonate, where the pH of an acid fluid is typically less than
about 3.5. The compositions of the present invention can be used to
help dissolve and remove carbonate materials from the formation
with less acidic compositions. In some applications, acidic
compositions can be damaging to the well or hydrocarbon
production.
[0016] Most preferably, according to the invention, the pH of the
treatment fluid is in the range of 6-12, which can be used to avoid
or reduce the use of substantially acidic compositions in treating
the formation. It is important to note, of course, that different
chelating agents work better in certain pH ranges than other
ranges. Some chelating agents can be effective in the higher pH
ranges. One skilled in the art would also recognize the obvious
advantage of using a non-acid fluid may reduce the rate of
corrosion.
[0017] In particular, the chelating agent is selected to be
effective for chelating at least calcium ions. It is also highly
desirable that the chelating agent is soluble in distilled water at
standard temperature and pressure at a concentration of at least
0.2 mole-equivalent for calcium ions per liter of the distilled
water. As a test for whether or not the chelating agent would be
effective for use in the present invention, it is believed that a
solution of the chelating agent at a concentration of 0.2
mole-equivalent for calcium ions per liter of the distilled water
should be effective for chelating at least 0.1 mole calcium ions
per liter. Preferably, the test solution is effective when adjusted
to have a pH in the range of 5-6. More preferably, the test
solution is effective when adjusted to have a pH in the range of
6-8. One skilled in the art would recognize that similar tests can
be performed for other ions such as magnesium, iron, etc.
[0018] There are numerous examples of suitable chelating agents.
For various reasons including effectiveness, ready availability,
and economical cost, the chelating agent is preferably selected
from the group consisting of ethylenediamine tetraacetic acid
("EDTA"), nitrilotriacetic acid ("NTA"),
hydroxyethylethylenediaminetriacetic acid ("HEDTA"),
diethylenetriaminepentaacetic acid ("DTPA"),
propylenediaminetetraacetic acid ("PDTA"),
ethylenediaminedi(o-hydroxyphenylacetic) acid ("EDDHA"), a sodium
or potassium salt of any of the foregoing, dicarboxymethyl glutamic
acid tetrasodium salt ("GLDA"), a derivative of any of the
foregoing or any combination in any proportion thereof. It is to be
understood, of course, that a derivative may be employed provided
that the substitution of an atom or group of atoms in the parent
compound for another atom or group of atoms does not substantially
impair the function of the derivative relative to the parent
compound. A derivative would also include compounds that do not
have the functionality, but would regain functionality due to some
process in use such as a reaction, hydrolysis, degradation, etc.
The chelating agent is preferably at a concentration of at least
0.01% by weight of the water. More preferably, the chelating agent
is at a concentration in the range of 1% to 80% by weight of the
water.
[0019] The viscosity-increasing agent would typically comprise a
polymeric material. For various reasons including effectiveness,
ready availability, and economical cost, the polymeric material is
preferably selected from the group consisting of: guar gum and its
derivatives, cellulose derivatives, welan gum, xanthan biopolymer
and its derivatives, diutan, and its derivatives, scleroglucan and
its derivatives, succinoglycan biopolymer and its derivatives, and
any combination of any of the foregoing in any proportion.
Derivatives can include, for example, industrially manufactured
chemical derivatives, bioengineered chemical derivatives, or
naturally occurring derivatives produced by mutated organisms
producing the polymer. A preferred polymer is of the nature taught
in U.S. Patent Application Serial No. 20060014648, which is
incorporated herein by reference in its entirety.
[0020] According to another aspect of the invention, the
viscosity-increasing agent can advantageously comprise a
viscoelastic surfactant. One perceived advantage of a surfactant
gel is that it has much less potential for leaving a polymer
residue. The viscoelastic surfactant may comprise any viscoelastic
surfactant known in the art, any derivative thereof, or any
combination thereof. As used herein, the term "viscoelastic
surfactant" refers to a surfactant that imparts or is capable of
imparting viscoelastic behavior to a fluid due, at least in part,
to the association of surfactant molecules to form viscosifying
micelles. These viscoelastic surfactants may be cationic, anionic,
nonionic, or amphoteric/zwitterionic in nature.
[0021] The viscoelastic surfactants may comprise any number of
different compounds, including methyl ester sulfonates (e.g., as
described in U.S. patent application Ser. Nos. 11/058,660,
11/058,475, 11/058,612, and 11/058,611, filed Feb. 15, 2005, each
of which is assigned to Halliburton Energy Services, Inc., the
relevant disclosures of which are incorporated herein by
reference), hydrolyzed keratin (e.g., as described in U.S. Pat. No.
6,547,871 issued Apr. 15, 2003 to Halliburton Energy Services,
Inc., the relevant disclosure of which is incorporated herein by
reference), sulfosuccinates, taurates, amine oxides, ethoxylated
amides, alkoxylated fatty acids, alkoxylated alcohols (e.g., lauryl
alcohol ethoxylate, ethoxylated nonyl phenol), ethoxylated fatty
amines, ethoxylated alkyl amines (e.g., cocoalkylamine ethoxylate),
betaines, modified betaines, alkylamidobetaines (e.g.,
cocoamidopropyl betaine), quaternary ammonium compounds (e.g.,
trimethyltallowammonium chloride, trimethylcocoammonium chloride),
derivatives of any of the foregoing, and any combinations of any of
the foregoing in any proportion.
[0022] Suitable viscoelastic surfactants may comprise mixtures of
several different compounds, including but not limited to: mixtures
of an ammonium salt of an alkyl ether sulfate, a cocoamidopropyl
betaine surfactant, a cocoamidopropyl dimethylamine oxide
surfactant, sodium chloride, and water; mixtures of an ammonium
salt of an alkyl ether sulfate surfactant, a cocoamidopropyl
hydroxysultaine surfactant, a cocoamidopropyl dimethylamine oxide
surfactant, sodium chloride, and water; mixtures of an ethoxylated
alcohol ether sulfate surfactant, an alkyl or alkene amidopropyl
betaine surfactant, and an alkyl or alkene dimethylamine oxide
surfactant; aqueous solutions of an alpha-olefinic sulfonate
surfactant and a betaine surfactant; and any combination of the
foregoing mixtures in any proportion. Examples of suitable mixtures
of an ethoxylated alcohol ether sulfate surfactant, an alkyl or
alkene amidopropyl betaine surfactant, and an alkyl or alkene
dimethylamine oxide surfactant are described in U.S. Pat. No.
6,063,738, issued May 16, 2000 to Halliburton Energy Services,
Inc., the relevant disclosure of which is incorporated herein by
reference. Examples of suitable aqueous solutions of an
alpha-olefinic sulfonate surfactant and a betaine surfactant are
described in U.S. Pat. No. 5,897,699, the relevant disclosure of
which is incorporated herein by reference. Examples of
commercially-available viscoelastic surfactants suitable for use in
the present invention may include, but are not limited to,
Mirataine BET-O 30.TM. (an oleamidopropyl betaine surfactant
available from Rhodia Inc., Cranbury, N.J.), Aromox APA-T.TM. (an
amine oxide surfactant available from Akzo Nobel Chemicals,
Chicago, Ill.), Ethoquad O/12 PG.TM. (a fatty amine ethoxylate quat
surfactant available from Akzo Nobel Chemicals, Chicago, Ill.),
Ethomeen T/12.TM. (a fatty amine ethoxylate surfactant available
from Akzo Nobel Chemicals, Chicago, Ill.), Ethomeen S/12.TM. (a
fatty amine ethoxylate surfactant available from Akzo Nobel
Chemicals, Chicago, Ill.), and Rewoteric AM TEG.TM. (a tallow
dihydroxyethyl betaine amphoteric surfactant available from Degussa
Corp., Parsippany, N.J.).
[0023] According to a preferred embodiment of the invention, the
viscosity-increasing agent is at a concentration in the treatment
fluid that is at least sufficient to make the viscosity of the
treatment fluid greater than water. More preferably, the
viscosity-increasing agent is at a concentration in the treatment
fluid that is sufficient to make the viscosity of the treatment
fluid greater than 5 cP when measured at 511 reciprocal seconds on
a Fann 35A model viscometer with a number 1 spring and bob. More
preferably, the viscosity-increasing agent is at a concentration in
the treatment fluid that is sufficient to make the viscosity of the
treatment fluid in the range of 10 cP to 100 cP when measured at
511 reciprocal seconds on a Fann 35A model viscometer with a number
1 spring and bob.
[0024] According to another preferred embodiment according to the
invention, the viscosity-increasing polymeric agent is at a
concentration of at least 0.05% by weight of the water. More
preferably, the viscosity-increasing agent is at a concentration in
the range of 0.05% to 10% by weight of the water.
[0025] It is contemplated that it will sometimes be desirable to
further increase the viscosity of the treatment fluid. One
technique for doing so is to crosslink a polymeric
viscosity-increasing agent. According to such an embodiment of the
invention, the treatment fluid further comprises a crosslinking
agent to crosslink the polymeric material of the
viscosity-increasing agent. A multitude of crosslinking agents for
such purposes are known in the art. Preferably, the crosslinking
agent is selected from the group consisting of: borate releasing
compounds, a source of titanium ions, a source of zirconium ions, a
source of antimony ions, a source of aluminum ions, a source of
periodate ions, a source of permanganate ions, and any combination
thereof in any proportion. According to a preferred embodiment, the
crosslinking agent is at a concentration of at least 0.025% by
weight of the water. According to a more preferred embodiment of
the invention, the crosslinking agent is at a concentration in the
range of 0.025% to about 1% by weight of the water. When the
treatment fluid for use in the methods according to the invention
includes a crosslinking agent, it can also be desirable for the
treatment fluid to further include a breaker for the crosslinked
agent.
[0026] According to another aspect of the invention, the treatment
fluid preferably further comprises a breaker adapted to break the
viscosity-increasing agent. For example, when the
viscosity-increasing agent is polysaccharide based, the breaker is
selected to be effective for breaking a polysaccharide-based
viscosity-increasing agent. The breaker can be, for example, an
enzyme. By way of further example, when the polysaccharide-based
viscosity-increasing agent includes starch, the enzyme is selected
to be effective for breaking starch. Preferably, an enzyme breaker
is at a concentration of at least 0.01 lb per 1000 gal of the
water. More preferably, the enzyme breaker is at a concentration in
the range of 0.01 lb to 40 lb per 1000 gal of the water. As will be
appreciated by persons of skill in the art, however, enzymes are
often used as liquid compositions and that the above mentioned
values are for fully formulated dry enzyme breakers that typically
contain a large percentage of fillers.
[0027] When a breaker is employed for the viscosity-increasing
agent, the breaker is at a concentration that is at least
sufficient to substantially reduce the viscosity produced by the
viscosity producing agent in the treatment fluid. In such case, a
preferred embodiment of the method according to the invention
includes the steps of allowing time for the breaker to break the
viscosity of the treatment fluid and then flowing back the broken
fluid from the wellbore.
[0028] For many types of viscosity-increasing agents, the breaker
is preferably an oxidizer selected from the group consisting of: a
persulfate; a perborate; a bromate; a periodate; a chlorate; a
chlorite; a hypochlorite, an organic peroxide; and any combination
thereof in any proportion. Further, the breaker is more preferably
selected from the group consisting of a lithium, sodium, potassium,
or ammonium salt of any of the foregoing, and any combination
thereof in any proportion. The oxidizing breaker for breaking a
viscosity-increasing agent internal to the treatment fluid is
preferably at a concentration of at least 0.01 lb per 1000 gal of
the water. More preferably, such a breaker is at a concentration in
the range of 0.1 to 200 per 1000 gal of the water.
[0029] It is contemplated that in some applications of the methods
according to the invention, it may be desirable that the breaker be
a delayed release breaker. One technique for making a delayed
breaker is to coat or encapsulate the breaker to delay the release
of the breaker into the water. Another technique is to generate the
breaker in situ over time or upon a change in pH of the treatment
fluid.
[0030] According to a preferred embodiment of the invention, the
method further includes the step of after introducing the treatment
fluid into the wellbore, allowing the viscosity of the treatment
fluid to break to a substantially lower viscosity fluid while down
hole. According to a further preferred embodiment, the method
further comprises the step of: after allowing the viscosity of the
treatment fluid to break, flowing the fluid back from the well.
[0031] According to further embodiments of the methods of the
invention, the treatment fluid can further comprise a breaker to be
carried by the treatment fluid into the wellbore for breaking a
viscosity-increasing agent that is external of the treatment fluid.
According to these embodiments, the breaker for the
viscosity-increasing agent in the treatment fluid is preferably at
a concentration in an external aqueous fluid that is at least
sufficient to substantially break the viscosity of the treatment
fluid. The breaker for a viscosity-increasing agent that is
external to the treatment fluid can be the same or different than
the breaker for the viscosity-increasing agent in the treatment
fluid. The additional or different breaker for breaking a
viscosity-increasing agent external to the treatment fluid is
preferably at a concentration of at least 0.01 lb per 1000 gal of
the water. More preferably, the breaker is at a concentration in
the range of 0.1 lb to 200 lb per 1000 gal of the water.
[0032] It is contemplated that the methods according to the
invention can include foaming of the treatment fluid. According to
these embodiments, the treatment fluid further comprises: an
additive for foaming. The treatment fluid may be formed at a remote
location and provided to the well site for the treatment method, or
it can be formed locally at the well site. The treatment fluid
preferably further comprises: a sufficient gas to form a foam. As
used herein, foam also refers to commingled fluids. Preferably, the
gas would be mixed with the other constituents of the treatment
fluid at the well site to form a foamed or co-mingled fluid.
According to a preferred embodiment of the invention, the gas is
selected from the group consisting of: air, CO.sub.2, nitrogen, and
any combination thereof in any proportion. In applications of the
method utilizing a gas, typically, the gas is at a concentration in
the range of 5% to 95% by volume of the water.
[0033] According to one aspect of the methods of the invention, the
step of introducing the treatment fluid into the wellbore further
comprises: introducing the treatment fluid at a rate and pressure
below the fracture gradient of the subterranean formation.
According to a further embodiment, the treatment fluid is applied
such that the treatment fluid is introduced such that the proppant
pack of a previously generated fracture or gravel pack is
treated.
[0034] As will be appreciated by those of skill in the art, in the
context of using a method according to the invention to treat a
portion of the subterranean formation surrounding a wellbore, the
permeability of the matrix of the surrounding formation would be
expected to be relatively high. According to a further embodiment,
the treatment fluid is applied such that the portion of the
subterranean formation is a portion surrounding the wellbore, and
wherein the treatment fluid is introduced such that the portion
surrounding the wellbore is expected to be saturated to a depth of
at least 1 foot. More preferably, the treatment fluid is applied
such that the portion surrounding the wellbore is expected to be
saturated to a depth in the range of 1 foot to 3 feet. Of course,
it is recognized that desired or expected depth of penetration into
the surrounding matrix of the formation will not necessarily be
perfectly uniform. It is also recognized that the parameters for
designing a treatment for a desired or expected depth of
penetration are well known in the art, including, for example, the
length of the wellbore to be treated and the volume of treatment
fluid injected into the wellbore. One skilled in the art will
recognize that a deeper penetration may be desired or obtained in
formations with higher permeability.
[0035] In some situations, the permeability of the matrix of the
surrounding formation would be expected to be relatively low.
According to another embodiment, the portion of the subterranean
formation is an area surrounding a fracture extending into the
formation, and the treatment fluid is introduced such that the
surrounding area is expected to be saturated to a depth of at least
0.1 inches. More preferably, the treatment fluid is introduced into
the wellbore under conditions such that the area surrounding the
fracture is expected to be saturated to a depth in the range of 0.1
inches to 2 inches. One skilled in the art will recognize that a
deeper penetration may be desired or obtained in formations with
higher permeability.
[0036] According to another embodiment, the portion of the
subterranean formation is a perforation tunnel, and the treatment
fluid is introduced such that the perforation tunnel and the
surrounding area is expected to be saturated to a depth of at least
0.1 inches. More preferably, the treatment fluid is introduced into
the wellbore under conditions such that the area surrounding the
perforation tunnel is expected to be saturated to a depth in the
range of 0.1 inches to 2 inches. One skilled in the art will
recognize that a deeper penetration may be desired or obtained in
formations with higher permeability.
[0037] One of skill in the art will further recognize that for the
purpose of treating the matrix of a proppant pack in a pre-existing
gravel pack, fracture, or perforation, it may not be necessary or
desirable to penetrate into the matrix of the surrounding
formation.
[0038] According to another aspect of the methods of the invention,
the methods further comprise the step of: after the step of
introducing the treatment fluid, introducing a non-viscosified
treatment fluid into the wellbore, wherein the non-viscosified
treatment fluid comprises: water and a chelating agent, without any
substantial concentration of any viscosity-increasing agent.
According to this aspect, the viscosified treatment fluid is
capable of moving into zones of the subterranean formation that
have relatively higher permeability, thereby diverting the
non-viscosified treatment fluid into zones of the subterranean
formation that have relatively lower permeability. According to
this aspect, the injection pressure is preferably maintained from
the step of introducing the treatment fluid to the step of
introducing the non-viscosified treatment fluid.
[0039] According to yet another aspect of the methods of the
invention, the methods further comprise the step of: applying an
afterflush fluid to the portion of the subterranean formation. For
example, the afterflush fluid can comprise: water, a gas, a brine,
a hydrocarbon, or a mixture thereof.
[0040] An example of a treatment fluid for use in the methods
according to the invention was formed as shown in the following
Table 1:
TABLE-US-00001 TABLE 1 Component Per 200 ml Per 1000 gallons Water
157.6 ml 788 US gals H4EDTA 98% 46.61 g 1987 lbs Potassium
Hydroxide Solid 96% 20.95 g 870 lbs Xanthan 0.96 g 40 lb/Mgal
[0041] The rheological properties of the example composition were
measured on a Fann Model 35 A viscometer as shown in the following
Table 2:
TABLE-US-00002 TABLE 2 300 rpm 600 rpm Dial Reading at room
temperature 21 29 Dial Reading at room temperature 29 35 after 4
hours at 175.degree. F.
[0042] Therefore, the methods of the present invention are well
adapted to carry out the objects and attain the ends and advantages
mentioned as well as those that are inherent therein. While
numerous changes may be made by those skilled in the art, such
changes are encompassed within the spirit of this invention as
defined by the appended claims.
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